Method for monitoring an area containing a subterranean resistive or conductive body, and for obtaining a volume of hydrocarbon therefrom

ABSTRACT

A method of analyzing electromagnetic survey data from an area of seafloor  6  that is thought or known to contain a resistive or conductive body, for example a subterranean hydrocarbon reservoir  12 , is described. The method includes providing horizontal electromagnetic field data obtained by at least one receiver  125  from at least one horizontal electric dipole transmitter  22 . Horizontal gradients in the electromagnetic field data are determined for a first component of the electromagnetic field data along a first direction and for a second component of the electromagnetic field data along a second direction. The first and second components can be the electric field along the first and second directions, or the magnetic field perpendicular to the first direction and second directions. The gradients are then combined to provide combined response data. Because the combined response data are relatively insensitive to the transverse electric (TE) mode component of the transmitted signal, the method allows hydrocarbon reservoirs to be detected in shallow water where the TE mode component interacting with the air would otherwise dominate.

RELATED APPLICATION DATA

This application is a continuation of U.S. patent application Ser. No.11/353,408 filed Feb. 14, 2006 now U.S. Pat. No. 7,362,102, which ishereby incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION

The invention relates to seafloor electromagnetic surveying forresistive and/or conductive bodies, for example for oil and otherhydrocarbon reserves or subterranean salt bodies.

FIG. 1 schematically shows a surface vessel 14 undertaking controlledsource electromagnetic (CSEM) surveying of a subterranean strataconfiguration using standard techniques [1]. The subterranean strataconfiguration in this example includes an overburden layer 8, anunderburden layer 9 and a hydrocarbon reservoir 12. The surface vessel14 floats on the surface 2 of a body of water, in this case seawater 4of depth h meters. A submersible vehicle 19 carrying a source in theform of a horizontal electric dipole HED transmitter 22 is attached tothe surface vessel 14 by an umbilical cable 16. This provides anelectrical and mechanical connection between the submersible vehicle 19and the surface vessel 14. The HED transmitter is supplied with a drivecurrent so that it broadcasts an HED electromagnetic (EM) signal intothe seawater 4. The HED transmitter is positioned a height z′ (typicallyaround 50 meters) above the seafloor 6. The EM signals comprisetransverse electric (TE) and transverse magnetic (TM) mode components.

One or more remote receivers 25 are located on the seafloor 6. Each ofthe receivers 25 include an instrument package 26, a detector 24, afloatation device 28 and a ballast weight (not shown). The detector 24comprises an orthogonal pair of horizontal electric dipole detectors andan orthogonal pair of horizontal magnetic field detectors positioned aheight z above the seafloor 6. Typically the detectors will lie on theseafloor so that z is in effect zero. The horizontal electric dipoledetectors are sensitive to horizontal components of the electric fieldsinduced by the HED transmitter in the vicinity of the receiver 25, andproduce electric field detector signals therefrom. The horizontalmagnetic field detectors are sensitive to horizontal components of themagnetic fields, for example the magnetic flux density, induced by theHED transmitter in the vicinity of the receiver 25, and produce magneticfield detector signals therefrom. The instrument package 26 records thedetector signals for later analysis. Examples of suitable receivers aredescribed by Constable [8] and U.S. Pat. No. 5,770,945 [9].

The HED transmitter 22 broadcasts EM signals that propagate outwardsboth into the overlying water column 4 and downwards into the seafloor 6and the underlying strata 8, 9, 12. At practical frequencies for thismethod and given the typical resistivity of the respective media 4, 8,9, 12, propagation occurs by diffusion of electromagnetic fields. Therate of decay in amplitude and the phase shift of the signal arecontrolled both by geometric spreading and by skin depth effects.Because in general the underlying strata 8, 9, 12 are more resistivethan the seawater 4, skin depths in the underlying strata 8, 9, 12 arelonger. As a result, electromagnetic fields measured by a receiverlocated at a suitable horizontal separation are dominated by thosecomponents of the transmitted EM signal which have propagated downwardsthrough the seafloor 6, along within the underlying strata 8, 9, 12, andback up to the detector 24 rather than directly through the seawater 4.

A sub-surface structure which includes a hydrocarbon reservoir, such asthe one shown in FIG. 1, gives rise to a measurable increase in thehorizontal electric field component amplitudes measured at the receiverrelative to a sub-surface structure having only water-bearing sediments.This is because hydrocarbon reservoirs have relatively highresistivities (typically 100 Ωm) compared to other subterranean strata(typically 1 Ωm) and so the EM signals are less attenuated. It is thisenhancement in horizontal electric field amplitudes which has been usedas a basis for detecting hydrocarbon reservoirs [1].

It is important when surveying for hydrocarbon reservoirs to carefullyconsider the orientation of the current flows induced by a transmittedEM signal. The response of seawater and subterranean strata (which willtypically comprise planar horizontal layers) to EM signals is generallyvery different for TE mode components of the transmitted signal, whichexcite predominantly horizontal current flows, and TM mode components,which excite significant components of vertical current flow.

For TE mode components, the coupling between the layers comprising thesubterranean strata is largely inductive. This means the presence ofthin resistive layers (which are indicative of hydrocarbon reservoirs)does not significantly affect the EM fields detected at the surface asthe large scale current flow pattern is not affected by the thin layer.On the other hand, for TM mode components, the coupling between layersincludes a significant galvanic component (i.e. due to the directtransfer of charge between layers). For the TM mode even a thinresistive layer strongly affects the EM fields detected at the receiversince the large scale current flow pattern is interrupted by theresistive layer. It is known therefore that a significant component ofthe TM mode is required to satisfactorily perform an EM survey in thefield of oil exploration.

However, sole reliance on the sensitivity of the TM mode components tothe presence of a thin resistive layer can lead to ambiguities. Theeffects on detected EM fields arising from the presence of a thinresistive layer can be indistinguishable from the effects arising fromother realistic large scale subterranean strata configurations. In orderto resolve these ambiguities it is known to determine the response ofthe subterranean strata to both TM mode components (i.e. inductivelycoupled) and TE mode components (i.e. galvanically coupled) [1]. The TEmode is most sensitive to large scale subterranean structures, whereasthe TM mode is more sensitive to thin resistive layers.

The HED transmitter 22 shown in FIG. 1 simultaneously generates both TEand TM mode components with the relative contribution of each mode tothe signal at the receiver depending on the HED source-receiverorientation. At receiver locations which are broadside to the HEDtransmitter axis, the TE mode dominates the response. At receiverlocations which are inline with the HED transmitter axis, the TM mode isstronger (although the TE mode is still present) [1, 2, 3, 4]. Theresponse at receiver locations in both the inline and broadsideconfigurations is governed by a combination of the TE and TM modecomponents, and these tend to work in opposition.

At inline receiver locations for a one-dimensional layered subterraneanstrata the electric fields induced at the receiver will be radial (i.e.parallel to a line joining the source to the receiver) while atbroadside receiver locations they will be azimuthal (i.e. perpendicularto a line joining the source to the receiver). For in-between locationsthe direction of the induced electric fields will depend on the relativecoupling between the transmitter and detector for the TE and TM modes,which will depend on the subterranean strata's resistivity structure,for example whether it contains a hydrocarbon layer. For this reason,with known surveying techniques it is important to measure theorientation of the detector so that the direction of the inducedelectric fields is known. However, it can be difficult to do thisaccurately which can lead to a significant source of error wheninterpreting data.

To determine the differing responses of subterranean strata to the TEand the TM modes it is known to rely on the geometric splitting of themodes, i.e. to collect electric field amplitude data for differentsource-receiver alignments. This approach provides complementaryhorizontal electric field amplitude data sets which are differentlysensitive to the TE and TM mode components of the transmitted EMsignals. During analysis, these complementary data sets are combined toreveal differences between the TE mode and TM mode coupling between thetransmitter and the detector. These differences are indicative of thepresence or not of a subterranean hydrocarbon reservoir.

A problem with the above described survey and analysis techniques isthat they do not generally provide good results for surveys made inshallow waters. This is due to the presence of an ‘airwave’ component inthe EM fields induced by the HED transmitter at the receiver. Thisairwave component is due to EM signals from the HED transmitter whichinteract with the air. Since air is non-conducting and hence causeslittle attenuation, the airwave component can dominate the fields at thereceiver. The airwave component is principally due to the TE modecomponents. This is because the TE mode components are efficientlyinductively coupled across the seawater-to-air interface. The TM modecomponents, on the other hand, do not couple well across this boundaryand consequently do not contribute significantly to the airwavecomponent. Because it has not interacted with the subterranean strata,the airwave component contains little information about subterraneanresistivity. Accordingly, if the airwave contributes a significantcomponent to the EM fields induced by the HED transmitter at thereceiver, the sensitivity of the technique to subterranean resistivitystructures, such as hydrocarbon reservoirs, is greatly reduced. The pathof an example airwave component is schematically shown in FIG. 1 by adotted line labeled AW. The magnitude of the airwave component isreduced as a function of separation between source and receiver only bygeometric spreading. However, the airwave component is stronglyattenuated by its passage through the conducting seawater. This meansthat in relatively deep water (large h) the airwave component is notvery significant at the receiver and as such does not present a majorproblem. However in shallow water (small h), the airwave component doesnot pass through as much seawater and thus makes a larger contributionto the EM fields induced by the HED transmitter at the receiver. Thiscontribution becomes greater still at increasing source-receiverhorizontal separations. This is because (other than due to geometricspreading) the strength of the airwave component is relatively constantover a wide range of horizontal separations since any extra distancetraveled by the airwave component is almost exclusively in thenon-attenuating air. Other components of the EM fields induced by theHED at the receiver, such as those which pass through the subterraneanstrata and are of interest, travel through lower resistivity media andbecome increasing attenuated as they travel further. For these reasons,the airwave component tends to dominate the EM fields induced by the HEDtransmitter at the receiver for surveys made in shallow water,especially at large source-receiver horizontal separations.

The existence of the airwave as a dominant component of the detectorsignals limits the applicability of the above described surveying andanalysis techniques. In shallow water the source-receiver separationsover which the techniques can be applied is much reduced. This not onlyleads to a need to employ more receiver locations to adequately cover agiven area, but also limits the depth beneath the seafloor to which thetechnique is sensitive. This can mean that a buried hydrocarbonreservoir in shallow water may not be detectable, even though the samereservoir would be detected in deeper water.

FIG. 2A is a graph schematically showing results of one-dimensionalmodeling of two example EM surveys of the kind shown in FIG. 1. Oneexample corresponds to a survey performed in deep water (dotted line)and the other to a survey performed in shallow water (solid line). Foreach model survey the amplitude of a horizontal electric field componentinduced at the receiver in response to the HED EM transmitter iscalculated per unit transmitter dipole moment and is plotted as afunction of horizontal separation r between the HED transmitter and thereceiver. For both model surveys, the subterranean strata configurationis a semi-infinite homogeneous half space of resistivity 1 Ωm. In thedeep-water example, the subterranean strata configuration is locatedbeneath an infinite extent of seawater. In the shallow-water example, itis located beneath a 500-meter depth of seawater. In both cases theseawater has resistivity 0.3 Ωm. The transmitter and receiver areseparated along a line which runs through the axis of the HEDtransmitter (inline orientation). It is the component of detectedelectric field resolved along this direction which is plotted in FIG.2A. The HED transmitter is driven by an alternating current (AC) drivesignal at a frequency of 0.25 Hz.

The effect of the airwave component on the amplitude of EM fieldsinduced by the HED transmitter at the receiver is clear. In thedeep-water model survey, where there is no airwave component (becausethe water depth is infinite), the calculated electric field amplitudefalls steadily with increasing horizontal separation. In theshallow-water model, however, where there is a strong airwave component,the rate of amplitude reduction sharply decreases at a source-receiverhorizontal separation of about 5000 m.

FIG. 2B is a plot showing the ratio, p, of the two curves shown in FIG.2A. The large deviations from unity seen in FIG. 2B highlight thedifference between these curves. Since the only difference between thetwo model surveys is the presence or not of an airwave component, theratio plotted in FIG. 2A effectively shows the relative strength of theairwave component in the detected signal compared to that which passesthrough the subterranean strata for the shallow-water model survey.

It is apparent from FIGS. 2A and 2B that at all but the very shortesthorizontal separations (less that 1000 m) the detected electric field issignificantly larger for the shallow-water model. For example, at ahorizontal separation of 2500 m, the amplitude of the detected signal inthe deep-water model survey is around 10⁻¹² V/Am². In the shallow-watermodel survey it is higher at around 10^(−11.5) V/Am². This is due to theadditional contribution of the airwave component. This level of increaseshows that the airwave component has an amplitude more than double thatof the component which has passed through the subterranean strata, andaccordingly over two-thirds of the detector signal carries almost noinformation about the subterranean strata. At greater horizontalseparations the airwave component dominates even more. In particular, itbecomes especially pronounced beyond around 5000 m. At this point thereis a break in the rate at which the detected electric field amplitudefalls with increasing horizontal separation. At a horizontal separationof around 7000 m, the airwave component in the shallow-water example hasan amplitude around twenty times greater than that of the signal whichpasses through the subterranean strata. This clearly imposes highrequirements for the signal-to-noise ratio of data collected over thesesorts of horizontal separations, as is generally the case when a smallsignal rides on a large background. It is apparent that the airwavesignificantly limits the usefulness of these surveying and analysistechniques in shallow water.

FIGS. 3A and 3B schematically show gray scale representations of themodeled sensitivity S of conventional CSEM surveying to resistivitystructure beneath the seafloor for two different water depths. For FIG.3A, the water depth h is infinite and for FIG. 3B it is 50 m. The modelsurveys are made at a transmission frequency of 0.25 Hz and the earth isassumed to be a uniform half-space of resistivity ρ=1 Ωm. Sensitivity isplotted as a function of depth d below seafloor and separation r betweensource and receiver. In deep water (FIG. 3A) the depth d below theseafloor to which the CSEM survey data are sensitive increases withsource-receiver separation (as a basic rule of thumb the data aresensitive to structure down to a depth of around half thesource-receiver separation). The effect of the airwave in shallow water(FIG. 3B) is to decrease the depth to which the data are sensitive. As aconsequence deep target detection becomes impossible.

One proposed solution to the problem of the airwave dominatingshallow-water surveys has been to rely on measurements of the verticalelectric field components [10]. This is because vertical electric fieldcomponents are less affected by the airwave. However, in practice therecan be difficulties with this approach in practical surveys. This isbecause measurements of vertical electric field are significantly moreprone to motion induced noise than more conventional measurements ofhorizontal components.

SUMMARY OF THE INVENTION

According to a first aspect of the invention, there is provided a methodof analyzing results from an electromagnetic survey of an area that isthought or known to contain a subterranean resistive or conductive body,comprising: providing horizontal electric or magnetic field dataobtained by at least one receiver from at least one horizontal electricdipole transmitter; determining a horizontal gradient in a firstcomponent of the electric or magnetic field data along a firstdirection; determining a horizontal gradient in a second component ofthe electric or magnetic field data along a second direction; andcombining the horizontal gradients along the first and second directionsto generate combined response data.

In this case, references to horizontal indicate that a significantcomponent, preferably a major component, of the respective signalsshould be aligned with the horizontal axes. It is not necessary that thesignals are perfectly aligned to the horizontal axes, although closealignment is preferred to provide a strong signal and reduce thecomplexity of analysis, for example alignment within +/−30° isdesirable.

The resistive or conductive body might be a body which is more resistivethan surrounding strata, such as a hydrocarbon reservoir (e.g. oil, gas,methane hydrate) or salt body, or a body which is more conductive thansurrounding strata, such as siliceous sediments.

The first component of the electric or magnetic field data may be theelectric field strength parallel to the first direction with the secondcomponent being the electric field strength parallel to the seconddirection. The gradients may be combined by forming their sum.

Alternatively, the first component may be the magnetic field strengthperpendicular to the first direction and the second component themagnetic field strength perpendicular to the second direction. Thegradients may be combined by forming their difference.

By generating combined response data in the analysis, it is possible toanalyze survey results taken in shallower water than has previously beenpossible. This is because the combined response data are less sensitiveto transverse electric (TE) mode components which have propagatedthrough air and which tend to dominate survey results analyzed withprevious methods.

Combined response data of this kind are functionally similar to verticalderivatives in vertical components of electromagnetic field data.Accordingly, the combined response data provide similar benefits tothose achievable with data from vertical electric field detectors, suchas the benefits described in GB 2402745 A [10]. However, with thepresent invention, these advantages are achieved without relying onvertical electromagnetic field measurements. This is beneficial because,as noted above, vertical field measurements can be more susceptible tonoise, particularly motion-induced noise caused by undersea watercurrents.

Furthermore, the combined response data are independent of theorientation of the first and second directions with respect to thetransmitter dipole. This means it is not necessary to know theorientation of receivers used to collect the data from which thecombined response data are derived.

The first and second directions may be orthogonal to one another. Thisprovides combined response data which are particularly insensitive tothe TE mode.

The horizontal gradients may be determined from measurements of electricor magnetic field made at horizontally separated locations.Alternatively, in accordance with the principle of reciprocity, thehorizontal gradients may equally be determined from transmissions ofelectromagnetic field made at horizontally separated locations.

The method may further comprise providing background data specific tothe area being surveyed and comparing the combined response data withthe background data to obtain difference data sensitive to the presenceof a subterranean resistive or conductive body.

This can be beneficial since the comparison of the combined responsedata with background data can help to determine whether features of thecombined response data are indicative of a resistive or conductive bodyor arise as a result of some other local background structureconfiguration. Background data may be obtained by modeling the EM surveyperformed to obtain the combined response data with a model backgroundsubterranean strata configuration. The background model strataconfiguration should preferably be a close match to the actualbackground structure in the area being surveyed.

The background data may be obtained in several ways, for example from acontrolled source electromagnetic survey, from a magneto-telluricelectromagnetic survey, from another similar survey taken at a differenttime, or from a rock formation model. If a rock formation model is usedit should preferably include resistivity, and may be derived from acombination of geological data and resistivity data. The geological datacan be from seismological surveying and the resistivity data from welllogging. Other sources of information, such as neutron data or otherporosity estimates from well logs, could also be used.

In some examples, the background data may be obtained fromelectromagnetic field data similar to that used to generate the combinedresponse data. This can be achieved by providing further horizontalelectric or magnetic field data and combining the data in a differentway. For example, by determining a horizontal gradient in a firstcomponent of the further electric or magnetic field data along a thirddirection; determining a horizontal gradient in a second component ofthe further electric or magnetic field data along a fourth direction;and combining the horizontal gradients along the third and fourthdirections to generate the background data.

In this case, the first component of the further electric or magneticfield data may be the electric field strength perpendicular to the thirddirection and the second component the electric field strengthperpendicular to the fourth direction. The horizontal gradients alongthe third and fourth directions may then be combined by forming theirdifference.

Alternatively, the first component of the further electric or magneticfield data may be the magnetic field strength parallel to the thirddirection and the second component the magnetic field strength parallelto the fourth direction. The horizontal gradients along the third andfourth directions may then be combined by forming their sum.

The third and fourth directions may be orthogonal to one another andthey may also be the same as respective ones of the first and seconddirections.

The difference data may represent the difference between the combinedresponse data and the background data as a function of position withinthe area surveyed, and the analysis may include identifying a locationof a boundary of a subterranean resistive or conductive body.

According to a second aspect of the invention there is provided acomputer program product bearing machine readable instructions forimplementing a method of analyzing results from an electromagneticsurvey according to the first aspect of the invention.

According to a third aspect of the invention there is provided acomputer apparatus loaded with machine readable instructions forimplementing the method of analyzing results from an electromagneticsurvey according to the first aspect of the invention.

According to a fourth aspect of the invention there is provided a methodof planning an electromagnetic survey of an area that is thought orknown to contain a subterranean resistive or conductive body,comprising: creating a model of the area to be surveyed including a rockformation containing a postulated resistive or conductive body, and abody of water above the rock formation; setting values for water depth,depth of the postulated resistive or conductive body, and resistivitystructure of the rock formation; and performing a simulation of anelectromagnetic survey in the model of the survey area by calculatinghorizontal electric or magnetic field data obtained by at least onesimulated receiver detecting signals from at least one simulatedhorizontal electric dipole transmitter; determining a horizontalgradient in a first component of the electric or magnetic field dataalong a first direction; determining a horizontal gradient in a secondcomponent of the electric or magnetic field data along a seconddirection; and combining the horizontal gradients along the first andsecond directions to generate combined response data.

The method may further comprise adjusting the model to remove thepostulated resistive or conductive body and repeating the simulation toobtain background data for comparison with the combined response data.

Repeated simulations for a number of source-receiver horizontalseparations and frequencies of signal can be performed in order to allowoptimum surveying conditions in terms of source-to-receiver distance andfrequency of EM signal for probing the resistive or conductive body tobe selected when performing an electromagnetic survey. The effects andusefulness of differing receiver array configurations and transmittertow paths can also be modeled.

Again, the resistive or conductive body might be a body which is moreresistive than surrounding strata, such as a hydrocarbon reservoir.

According to a fifth aspect of the invention there is provided acomputer program product bearing machine readable instructions forimplementing the method of planning an electromagnetic survey accordingto the fourth aspect of the invention.

According to a sixth aspect of the invention there is provided acomputer apparatus loaded with machine readable instructions forimplementing the method of planning an electromagnetic survey accordingto the fourth aspect of the invention.

According to a seventh aspect of the invention there is provided anelectromagnetic receiver for use in an electromagnetic survey of an areathat is thought or known to contain a subterranean resistive orconductive body, wherein the receiver comprises two pairs of electric ormagnetic dipole detectors, a first pair of which are separated along afirst direction and a second pair of which are separated along a seconddirection, the first and second directions being horizontal when thereceiver is in normal use.

The first pair of dipole detectors may be electric dipole detectorsaligned with their axes substantially parallel to the first directionand the second pair of dipole detectors may be electric dipole detectorsaligned with their axes substantially parallel to the second direction.

The first pair of dipole detectors may comprise at least threeelectrodes separated along the first direction and the second pair ofdipole detectors may comprise at least three electrodes separated alongthe second direction.

Furthermore, a single common electrode may provide one of the electrodesof the first pair of dipole detectors and one of the electrodes of thesecond pair of dipole detectors.

Alternatively, the first pair of dipole detectors may be horizontalmagnetic dipole detectors aligned with their axes substantiallyperpendicular to the first direction and the second pair of dipoledetectors may be horizontal magnetic dipole detectors aligned with theiraxes substantially perpendicular to the second direction.

In this case, the first pair of dipole detectors may comprise a pair ofcoils with each coil arranged in a plane which is vertical when thereceiver is in normal use and parallel to the first direction and thesecond pair of dipole detectors may comprise a pair of coils with eachbeing arranged in a plane which is vertical when the receiver is innormal use and parallel to the second direction.

The first and second directions may be orthogonal to one another.

The receiver may further comprise two further pairs of electric ormagnetic dipole detectors, a first pair of which are separated along athird direction and a second pair of which are separated along a fourthdirection, the third and fourth directions being horizontal when thereceiver is in normal use.

The first pair of further dipole detectors may be horizontal electricdipole detectors aligned with their axes substantially perpendicular tothe third direction and the second pair of further dipole detectors maybe horizontal electric dipole detectors aligned with their axessubstantially perpendicular to the fourth direction.

Alternatively, the first pair of further dipole detectors may bemagnetic dipole detectors aligned with their axes substantially parallelto the third direction and the second pair of further dipole detectorsmay be magnetic dipole detectors aligned with their axes substantiallyparallel to the fourth direction.

The third and fourth directions may be orthogonal to one another.Furthermore, the third and fourth directions may be the same asrespective ones of the first and second directions.

Receivers of the seventh aspect of the invention may be used to providedata for analysis according to the first aspect of the invention.

According to an eighth aspect of the invention there is provided anelectromagnetic survey method applied to a survey area that is thoughtor known to contain a subterranean resistive or conductive body,comprising: providing at least one transmitter and at least one receiveraccording to the seventh aspect of the invention for respectivetransmission and detection of electromagnetic signals; and obtainingelectromagnetic field data by detection and/or transmission at aplurality of different locations over the survey area.

Such a survey method provides data which allow gradients in electricfield data to be determined such that the data may be analyzed accordingto the methods of the first aspect of the invention.

According to a ninth aspect of the invention there is provided anelectromagnetic source for use in an electromagnetic survey of an areathat is thought or known to contain a subterranean resistive orconductive body, wherein the source comprises two pairs of electric ormagnetic dipole transmitters, a first pair of which are separated alonga first direction and a second pair of which are separated along asecond direction, the first and second directions being horizontal whenthe source is in normal use.

The first pair of dipole transmitters may be aligned with their axessubstantially parallel to the first direction and the second pair ofdipole transmitters may be aligned with their axes substantiallyperpendicular to the second direction.

The first and second directions are orthogonal to one another.

Sources according to the ninth aspect of the invention may be used toprovide data for analysis according to the first aspect of theinvention.

According to an tenth aspect of the invention there is provided anelectromagnetic survey method applied to a survey area that is thoughtor known to contain a subterranean resistive or conductive body,comprising: providing at least one source according the ninth aspect ofthe invention and at least one receiver for respective transmission anddetection of electromagnetic signals; and obtaining electromagneticfield data by transmission and/or detection at a plurality of differentlocations over the survey area.

Such a survey method provides data which allow gradients in electricfield data to be determined such that the data may be analyzed accordingto the methods of the first aspect of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

For a better understanding of the invention and to show how the same maybe carried into effect reference is now made by way of example to theaccompanying drawings, in which:

FIG. 1 shows in schematic vertical section a surface vessel undertakingan EM survey in deep water according to standard techniques;

FIG. 2A is a graph plotting detector signals calculated from two modelsurveys analyzed according to the previously proposed method, oneperformed in deep water (dotted line) and one performed in shallow water(solid line);

FIG. 2B is a graph plotting the ratio of the two curves shown in FIG.2A;

FIGS. 3A and 3B schematically show the sensitivity of a modeled CSEMsurvey to subterranean resistivity for two different water depths;

FIG. 4 is a plan view showing a cylindrical polar co-ordinate system;

FIGS. 5A-5F show equations (Equations 1 to 6) corresponding to solutionsto Maxwell's equations for an HED transmitter in a finite seawater layeroverlying a one-dimensional subterranean resistivity structure for theradial (r), azimuthal (φ) and vertical (z) components of the electric(E) and magnetic (B) fields;

FIG. 5G shows an equation (Equation 7) defining a linear combination ofgradients in horizontal electric field data measured along orthogonaldirections which is used in a method of analyzing survey data accordingto an embodiment of the invention;

FIG. 5H shows an equation (Equation 8) defining a linear combination ofgradients in horizontal magnetic field data measured along orthogonaldirections which is used in a method of analyzing survey data accordingto an embodiment of the invention;

FIG. 6 schematically shows in vertical section a surface vesselundertaking an EM survey according to an embodiment of the invention;

FIGS. 7A and 7B show the modeled amplitude and phase of the radialcomponent of electric field data collected during a conventional EMsurvey of the model subterranean strata configuration shown in FIG. 6for a range of water depths;

FIGS. 7C and 7D show the modeled amplitude and phase of the verticalcomponent of electric field data collected during a previously proposedEM survey of the model subterranean strata configuration shown in FIG. 6for a range of water depths;

FIGS. 7E and 7F show the modeled amplitude and phase of a combination ofhorizontal gradients in electric field data collected during an EMsurvey of the model subterranean strata configuration shown in FIG. 6which provides electric TM mode decomposition data according to anembodiment of the invention for a range of water depths;

FIG. 8 shows in schematic vertical section a model hydrocarbon-reservoirbearing subterranean strata configuration;

FIGS. 9A and 9B show the modeled amplitude and phase of the radialcomponent of electric field data collected during a conventional EMsurvey of the model subterranean strata configuration shown in FIG. 8for a range of hydrocarbon reservoir resistivities;

FIGS. 9C and 9D show the modeled amplitude and phase of the verticalcomponent of electric field data collected during a previously proposedEM survey of the model subterranean strata configuration shown in FIG. 8for a range of hydrocarbon reservoir resistivities;

FIGS. 9E and 9F show the modeled amplitude and phase of a combination ofhorizontal gradients in electric field data collected during an EMsurvey of the model subterranean strata configuration shown in FIG. 8which provides electric TM mode decomposition data according to anembodiment of the invention for a range of hydrocarbon reservoirresistivities;

FIG. 10A is a graph schematically showing the ratio of the curvesplotted in FIGS. 9A (radial electric field component), 9C (verticalelectric field component) and 9E (electric TM mode decomposition) for ahydrocarbon reservoir of resistivity ρ=100 Ωm to the correspondingcurves for which there is no detectable hydrocarbon reservoir;

FIG. 10B is a graph schematically showing the difference in phasebetween the curves plotted in FIGS. 9B (radial electric fieldcomponent), 9D (vertical electric field component) and 9F (electric TMmode decomposition) for a hydrocarbon reservoir of resistivity ρ=100 Ωmand the respective corresponding curves for which there is no detectablehydrocarbon reservoir;

FIG. 11A shows in schematic vertical section a modelhydrocarbon-reservoir bearing subterranean strata configuration;

FIG. 11B shows in schematic vertical section a modelincreasing-resistivity subterranean strata configuration in whichresistivity progressively increases with depth;

FIG. 12A is a graph schematically showing the ratios of electric TM modedecomposition data calculated for the model subterranean strataconfigurations shown in FIGS. 11A and 11B to those calculated for thebackground model subterranean strata configuration shown in FIG. 6 forinfinite water depth;

FIG. 12B is a graph schematically showing the ratios of electric TE modedecomposition data calculated for the model subterranean strataconfigurations shown in FIGS. 11A and 11B to those calculated for thebackground model subterranean strata configuration shown in FIG. 6 forinfinite water depth;

FIG. 13A shows an equation (Equation 9) defining a linear combination ofgradients in horizontal electric field data measured along orthogonaldirections which is used in a method of analyzing survey data accordingto an embodiment of the invention;

FIG. 13B shows an equation (Equation 10) defining a linear combinationof gradients in horizontal magnetic field data measured along orthogonaldirections which is used in a method of analyzing survey data accordingto an embodiment of the invention;

FIGS. 14A-14C show example detector configurations which may be used toobtain TM mode decomposition data;

FIGS. 14D and 14E show example detector configurations which may be usedto obtain TE mode decomposition data;

FIGS. 15A and 15B show schematic gray scale representations of themagnitude of modeled electric TM mode decomposition data obtained forthe subterranean strata configuration shown in FIG. 11A for a practicaldetector and an idealized detector respectively;

FIGS. 15C and 15D show schematic gray scale representations of the phaseof modeled electric TM mode decomposition data obtained for thesubterranean strata configuration shown in FIG. 11A for a practicaldetector and an idealized detector respectively;

FIGS. 16A and 16B show percentage errors between TM mode decompositiondata obtained at locations inline with a transmitter for a number ofdifferent practical detector configurations relative to an idealizeddetector;

FIGS. 17A and 17B show schematic gray scale representations of themagnitude of modeled electric TM mode decomposition data obtained forthe subterranean strata configuration shown in FIG. 11A for an array ofrandomly oriented detectors and an array of aligned detectorsrespectively;

FIGS. 18A and 18B show schematic gray scale representations of the phaseof modeled electric TM mode decomposition data obtained for thesubterranean strata configuration shown in FIG. 11A for an array ofrandomly oriented detectors and an array of uniformly aligned detectorsrespectively;

FIGS. 19A and 19B show percentage errors between TM mode decompositiondata obtained at locations inline with a transmitter for an array ofrandomly oriented detectors relative to an array of uniformly aligneddetectors;

FIGS. 20A and 20B show percentage errors between TM mode decompositiondata obtained at locations inline with a transmitter for a detector withtranslationally skewed arms relative to an idealized detector;

FIGS. 21A and 21B show percentage errors between TM mode decompositiondata obtained at locations inline with a transmitter for a detector witha rotationally skewed arms relative to an idealized detector;

FIG. 22A schematically shows in vertical section a 3D model subterraneanstrata configuration;

FIG. 22B schematically shows in horizontal section the modelsubterranean strata configuration shown in FIG. 22A;

FIGS. 23A and 23B show schematic gray scale representations of themagnitude and phase of modeled electric TM mode decomposition dataobtained for the subterranean strata configuration shown in FIG. 22A andfor a similar model having a hydrocarbon reservoir of infinitehorizontal extent;

FIGS. 24A and 24B schematically show the magnitude and phase of modeledTM mode decomposition data obtained at locations inline with atransmitter for the subterranean strata configuration shown in FIG. 22Aand for a similar model having a hydrocarbon reservoir of infinitehorizontal extent;

FIGS. 25A and 25B and FIGS. 26A and 26B are similar to FIGS. 23A and 23Band FIGS. 24A and 24B respectively, but show the data normalized to auniform background subterranean strata configuration;

FIGS. 27A and 28A show schematic gray scale representations of the datashown in FIG. 23A, but scaled by an additional factor corresponding tothe distance between the transmitter and receiver squared and cubedrespectively;

FIGS. 27B and 28B schematically show the magnitude of the modeled TMmode decomposition data shown in FIG. 24A, but scaled by an additionalfactor corresponding to the distance between the transmitter andreceiver squared and cubed respectively;

FIGS. 29A and 29B show an example source configuration which may be usedto obtain TM mode decomposition data; and

FIG. 30 shows another example source configuration which may be used toobtain TM mode decomposition data.

DETAILED DESCRIPTION

FIG. 4 is a schematic plan view showing a co-ordinate system fordescribing the relative placement of an HED transmitter 22 and areceiver 25 of the kind shown in FIG. 1. The position of the receiver 25with respect to the HED transmitter 22 is most suitably described incylindrical polar co-ordinates, with the center of the HED transmitter22 providing the origin of the co-ordinate system. The position of thereceiver 25 is defined by an azimuthal angle φ and a separation distance(or range) r. The angle φ is measured clockwise from a line passingthrough, and running parallel to, the HED transmitter axis, as indicatedin FIG. 4 by the line marked φ=0°. A receiver placed along this line,i.e. such that is has an azimuthal angle φ of 0°, is referred to asbeing in an inline or end-on position. A receiver with an azimuthalangle φ of 90°, such that it lies on the line marked φ=90° in FIG. 4, isreferred to as being in a broadside position. The electric field at areceiver may be considered to be resolved into a radial component E_(r)and an orthogonal azimuthal component E_(φ), as indicated in the figure.The magnetic flux density at the receiver may similarly be considered tobe resolved into a radial component B_(r) and an orthogonal azimuthalcomponent B_(φ). The axial co-ordinate z extends vertically away fromthe seafloor.

The fundamental equations governing electromagnetic induction in theearth are Maxwell's equations. At frequencies typically used in CSEMsurveys displacement currents can be neglected to give: ∇.B=0, ∇.E=0,∇×E+iωB=0 and ∇×B−iων₀ε₀ E=ν₀ J, where E is the electric field strength,B is the magnetic flux density, σ is the conductivity of the medium, ν₀is the magnetic permeability (assumed to take its free space value), ε₀is the electric permittivity of free space, J is the source currentdensity, and a single Fourier component proportional to e^(jωt) isconsidered. Maxwell's equations can be solved numerically in two- orthree-dimensions for a point HED transmitter, however a closed formexists only for one-dimensional structures. Chave & Cox [7] derive asolution for the case of an HED transmitter in an infinite depth ofseawater for a one-dimensional subterranean strata configuration (i.e.in which resistivity varies only in the vertical z-direction).

The inventors have performed an extension of the analysis presented inChave & Cox [7] to model an HED transmitter in a finite depth h ofseawater. Solving Maxwell's equations for an HED transmitter in a finiteseawater layer overlying a one-dimensional subterranean resistivitystructure provides equations for the radial (r), azimuthal (φ) andvertical (z) components of the electric field (E) and magnetic fluxdensity (B) as shown in FIGS. 5A to 5F. Although this modeling has beenperformed for a one-dimensional strata configuration, similar modelingmay be performed in two- or three-dimensions.

Where the “±” or the “∓” optional operator appears in these equation (orany other equations presented herein), the upper symbol is used whenz′>z and the lower symbol when z′<z. In these equations, z′ and z arethe heights of the HED transmitter and detector above the seafloorrespectively, h is the depth of the seawater, μ₀ is the permeability offree space, P is the transmitter dipole moment,

${J_{0}({kr})} = {{\sum\limits_{l = 0}^{\infty}{\frac{\left( {- 1} \right)^{l}}{2^{2l}\left( {l!} \right)^{2}}({kr})^{2l}\mspace{14mu}{and}\mspace{14mu}{J_{1}({kr})}}} = {\sum\limits_{l = 0}^{\infty}{\frac{\left( {- 1} \right)^{l}}{2^{{2l} + 1}{l!}\left( {1 + {l!}} \right)}({kr})^{{2l} + 1}}}}$are zeroth and first order Bessel functions respectively, ρ₀ is theresistivity of the seawater, k is a parameter analogous to the wavenumber in a Fourier integral,

${\beta_{0} = \sqrt{k^{2} - \frac{{\mathbb{i}\omega\mu}_{0}}{\rho_{0}}}},$R_(L) ^(TM) and R_(L) ^(TE) are coefficients defining the TM and TE modeinteraction with the seafloor which depend on the resistivity structureof the subterranean strata configuration, and R_(A) ^(TE) is acoefficient defining the TE mode interaction with the air.

In the presentation of Equations 1, 2, 4 and 5 (which are the equationsdescribing the horizontal components of the fields) in FIGS. 5A, 5B, 5Dand 5E, the equations are shown split over four lines of text with eachline of text having a left and a right component. The left component oneach line is marked “TM” and results from the TM mode component of thetransmitted signal and the right component is marked “TE” and resultsfrom the TE mode component of the transmitted signal.

As previously noted, the airwave component is principally due to theinteraction of the TE mode with the air, i.e. determined by the R_(A)^(TE) coefficient. As can be seen from Equations 1 and 2, E_(r) andE_(φ) include both TM and TE components and so are affected by theairwave. This is why known methods of analyzing results from CSEMsurveys based on electric field amplitude enhancement do not work wellin shallow water.

Equation 7, shown in FIG. 5G, defines a linear combination of a gradientin electric field data along a first horizontal direction x (i.e.∂E_(x)/∂x) and a gradient in electric field data along a secondorthogonal horizontal direction y (i.e. ∂E_(y)/∂y) which is used in amethod of analyzing results according to an embodiment of the invention.

Equation 8, shown in FIG. 5H, defines a linear combination of ahorizontal gradient along the x-direction of magnetic field datameasured along y (i.e. ∂B_(y)/∂x) and a horizontal gradient along they-direction of magnetic field data measured along x (i.e. ∂B_(x)/∂y)used in a method of analyzing results according to another embodiment ofthe invention.

Combinations of electric or magnetic field data such as shown in FIGS.5G and 5H are referred to as combined response data. It is noted thatwhile the x- and y-directions are orthogonal to one another, theirabsolute orientation about a vertical z-axis is completely arbitrary.That is to say, the combined response data defined by the equationsshown in FIGS. 5G and 5H do not depend on the actual directions alongwhich the field data are measured, so long as the directions areorthogonal.

While the horizontal field components of electric field and magneticflux density are both TM and TE dependant (see Equations 1, 2, 4 and 5),the combinations shown in Equations 7 and 8 depend only on the TM mode.For this reason the combined response data defined by Equations 7 and 8are referred to as TM mode decomposition data. In particular, the TMmode decomposition shown in Equation 7 is referred to as electric TMmode decomposition data and the TM mode decomposition shown in Equation8 is referred to as magnetic TM mode decomposition data.

Because the TM mode decomposition data does not include any dependenceon the TE mode, the TM mode decomposition data are much less sensitiveto the airwave component which prevents conventional analysis methodsfrom working well in shallow water. For Equation 7, the lack ofdependence on the TE mode is a consequence of the lack of dependence ofEz on the TE mode (see Equation 3), and the conservation of electricfield flux in the absence of electric charges. That is to say,

${{\nabla{\cdot \underset{\_}{E}}} = {{\frac{\partial{Ex}}{\partial x} + \frac{\partial{Ey}}{\partial y} + \frac{\partial{Ez}}{\partial z}} = 0}},$therefore

${{\frac{\partial{Ex}}{\partial x} + \frac{\partial{Ey}}{\partial y}} = {- \frac{\partial{Ez}}{\partial z}}},$and because

$\frac{\partial{Ez}}{\partial z}$is TE independent (because Ez is TE independent),

$\frac{\partial{Ex}}{\partial x} + \frac{\partial{Ey}}{\partial y}$is also TE independent. Equation 8 is TE independent because

${{\frac{\partial{By}}{\partial x} - \frac{\partial{Bx}}{\partial y}} \propto {Ez}},$from the projection of Maxwell's equation for the curl of magnetic fieldonto the z-axis in the absence of displacement currents.

FIG. 6 schematically shows a surface vessel 14 undertaking controlledsource electromagnetic (CSEM) surveying of a subterranean strataconfiguration using a survey method according to an embodiment of theinvention. The surface vessel 14 floats on the surface 2 of a body ofwater, in this case seawater 4 of depth h meters. A submersible vehicle19 carrying a source in the form of an HED transmitter 22 is attached tothe surface vessel 14 by an umbilical cable 16 providing an electricaland mechanical connection between the submersible vehicle 19 and thesurface vessel 14. The HED transmitter is supplied with a drive currentso that it broadcasts an HED EM signal into the seawater 4. The HEDtransmitter is positioned a height z′ (typically around 50 meters) abovethe seafloor 6. The surface vessel 14, submarine 19, umbilical 16 andHED transmitter 22 may be conventional.

One or more remote receivers 125 are located on the seafloor 6. Each ofthe receivers 25 includes an instrument package 126, a detector 124, afloatation device 128 and a ballast weight (not shown). Each detector isable to measure electric field gradients in two orthogonal horizontaldirections to allow electric TM mode decomposition data as defined byEquation 7 to be obtained. In this example, the detectors are also ableto measure magnetic field gradients in two orthogonal horizontaldirections to allow magnetic TM mode decomposition data as defined byEquation 8 to be obtained. Examples of suitable detectors are describedfurther below. The detectors are positioned at or just above theseafloor. The instrument package 126 records the signals from thedetector for later analysis.

In FIG. 6, the survey takes place over a model background subterraneanstrata configuration. In this configuration the seawater has aresistivity of 0.3 Ωm and beneath the seafloor 6 is a uniform half-spacesedimentary structure with a resistivity of 1 Ωm. The low resistivity ofthe sedimentary structure is primarily due to aqueous saturation of porespaces. This sedimentary structure extends uniformly downwards for aninfinite extent.

FIG. 7A is a graph schematically showing the logarithm of the modeledradial electric field component amplitude, Log₁₀(E), seen at a receiverin an inline orientation (i.e. φ=0) in response to the HED transmitterbroadcast signal as a function of separation, r, between the transmitterand the receiver. This is the field component previously used as thebasis for the analysis of CSEM survey data and is shown here forcomparison purposes. Curves are shown for a number of different waterdepths (H=1500 m, 1000 m, 500 m, 200 m and 100 m) as indicated on thefigure. The HED transmitter is driven by an AC drive signal at afrequency of 0.25 Hz and the electric fields are calculated per unittransmitter electric dipole moment. FIG. 7A demonstrates how the radialcomponent of the electric field given by Equation 1 becomes increasinglydominated by the airwave component of the transmitted signal inshallower water. For example, at a separation of around 9000 m, thecalculated radial electric field is approximately 300-times greater in awater depth of 100 m than in a water depth of 1500 m. This is due to theincreased relative contribution of the airwave component. Even atseparations of only around 2000 m, the increased airwave contributionseen with a water depth of 100 m leads to radial electric fields whichare around ten-times greater than those seen in deeper waters.

FIG. 7B is a graph schematically showing the phase, χ, relative to theHED transmitter AC drive signal, of the modeled radial electric fieldcomponents plotted in FIG. 7A. It is apparent from FIG. 7B that with afinite water depth there is little advance in phase with increasingseparation once the airwave component begins to dominate, for example atbeyond around r=2000 m for h=100 m. This is because a dominant componentof the signal is travelling rapidly through the non-conducting air.

FIGS. 7C and 7D are similar to and will be understood from FIGS. 7A and7B respectively. However, whereas FIGS. 7A and 7B show radial electricfield data, FIGS. 7C and 7D show data for vertical components ofelectric field as a function of separation r. These curves show there islittle dependence on water depth h for the vertical electric fieldcomponent. It is for this reason that vertical electric field data havebeen previously proposed for shallow-water surveying [10].

FIG. 7E is a graph schematically showing the logarithm of the modeledelectric TM mode decomposition given by Equation 7 seen at the receiver125 in response to the HED transmitter broadcast signal multiplied bysource-receiver separation, r, as a function of this separation for aninline orientation. For other azimuths φ, the curves would befunctionally similar but scaled by a factor cos(φ). The multiplicationby r provides for an equivalent electric field parameterization of theTM mode decomposition. As with FIGS. 7A and 7C, curves are calculatedfor a number of different water depths h. The HED transmitter is againdriven by an AC drive signal at a frequency of 0.25 Hz and the TM modedecomposition calculated per unit transmitter electric dipole moment. Itis clear from FIG. 7E that, unlike FIG. 7A, there is little differencebetween the curves for the different water depths. This reflects thefact that, as with the vertical component of electric field shown inFIG. 7C, the TM mode decomposition does not include a TE mode dependencewhich is the mode which contributes most to the airwave component.

FIG. 7F is a graph schematically showing the phase, χ, relative to theHED transmitter AC drive signal, of the modeled TM mode decompositionplotted in FIG. 7E. It is apparent from FIG. 7F that the phase advancessteadily with increasing separation for all water depths. This againdemonstrates the insensitivity of the TM mode decomposition given byEquation 7 to the airwave component in shallow water.

Although not shown, curves similar to those shown in FIGS. 7E and 7F butcalculated for the magnetic TM mode decomposition given by Equation 8demonstrate the insensitivity of the magnetic TM mode decomposition tothe airwave component also.

The insensitivity of the TM mode decompositions to the airwave componentin shallow water has been seen for the model background subterraneanstrata configuration shown in FIG. 6. However, this model does notcontain a hydrocarbon reservoir. It is, therefore, important to showthat the TM mode decompositions are sensitive to the presence of ahydrocarbon reservoir if they are to be of practical use.

FIG. 8 shows in schematic vertical section a model hydrocarbon-reservoirsubterranean strata configuration. A section of seafloor 6 lies beneatha 100 m depth of seawater 4 which has a resistivity of 0.3 Ωm. Thestrata configuration beneath the seafloor 6 comprises a 1000 m thickoverburden layer 8, representing sediments, arranged above a hydrocarbonreservoir 12. The overburden layer 8 has a resistivity of 1 Ωm, again,primarily due to aqueous saturation of pore spaces. The hydrocarbonreservoir 12 is 100 m thick, and has a resistivity of ρ Ωm. Thisresistivity will typically be greater than that of the surroundinglayers due to the presence of non-conducting hydrocarbon within porespaces. Below the hydrocarbon reservoir 12 is a sedimentary underburdenlayer 9, which, as for the overburden layer, has a resistivity of 1 Ωm.The underburden layer extends downwardly for an effectively infiniteextent. Accordingly, except for the presence or absence of thehydrocarbon reservoir 12, the hydrocarbon-reservoir subterranean strataconfiguration of FIG. 8 is identical to the background subterraneanstrata configuration of FIG. 6 for the case h=100 m. An HED transmitter22 and a receiver 125 are again shown.

FIG. 9A is a graph schematically showing the logarithm of the modeledradial electric field component amplitude, Log₁₀(E), seen at a receiverin response to the HED transmitter broadcast signal as a function ofseparation, r, between the transmitter and the receiver with thehydrocarbon-reservoir subterranean reservoir shown in FIG. 8. Thisconventionally used field component is again shown for comparisonpurposes. Curves are calculated for a number of different resistivitiesρ for the hydrocarbon reservoir (ρ=1 Ωm (i.e. effectively no detectablereservoir), 10 Ωm, 20 Ωm, 50 Ωm and 100 Ωm) as indicated on the figure.The HED transmitter is again driven by an AC drive signal at a frequencyof 0.25 Hz and the electric fields are calculated per unit transmitterelectric dipole moment. The curves shown in FIG. 9A are all very similarto one another, even though there is a wide range of reservoirresistivities. This is because with a water depth of only 100 m, theradial electric field component is dominated by the airwave component ofthe TE mode and cannot be used to properly identify the presence or notof a hydrocarbon reservoir.

FIG. 9B is a graph schematically showing the phase, χ, relative to theHED transmitter AC drive signal, of the modeled radial electric fieldcomponents plotted in FIG. 9A. It is apparent from FIG. 9B that there islittle advance in phase with increasing separation for all reservoirresistivities. This is again because a dominant component of thetransmitted signal is travelling through the non-conducting air.

FIGS. 9C and 9D are similar to and will be understood from FIGS. 9A and9B respectively. However, whereas FIGS. 9A and 9B show radial electricfield data, FIGS. 9C and 9D show data for vertical components ofelectric field. These curves show that unlike the radial electric fielddata, the vertical electric field data are sensitive tohydrocarbon-reservoir resistivity. It is again for this reason thatvertical electric field data have been previously proposed forshallow-water surveying [10].

FIG. 9E is a graph schematically showing the logarithm of the modeledelectric TM mode decomposition seen at the receiver 125 in response tothe HED transmitter 22 broadcast signal multiplied by source-receiverseparation as a function of this separation for thehydrocarbon-reservoir subterranean strata configuration of FIG. 8. Asbefore, the multiplication by r provides an equivalent electric fieldparameterization of the TM mode decomposition. As with FIG. 9A, curvesare calculated for a number of different hydrocarbon reservoirresistivities. The HED transmitter is again driven by an AC drive signalat a frequency of 0.25 Hz and the TM mode decomposition calculated perunit transmitter electric dipole moment. It is clear from FIG. 9E that,unlike the airwave dominated radial electric field curves of FIG. 9A,there is a strong dependence in the calculated response of the TM modedecomposition on the resistivity of the hydrocarbon reservoir, eventhough the seawater depth is only 100 m. Furthermore, unlike the datashown in FIG. 9C, this sensitivity to hydrocarbon reservoir is achievedwithout the use of vertical dipole detectors which are prone to noise.In effect, the TM mode decomposition data are functionally similar tovertical electric field data, but are obtained from horizontalmeasurements of electric field.

For a hydrocarbon-reservoir resistivity of ρ=100 Ωm, the TM modedecomposition signal is around 300-times greater at a separation ofr=11000 m than for the case ρ=1 Ωm (i.e. effectively no detectablehydrocarbon reservoir). This clearly demonstrates the sensitivity of theelectric TM mode decomposition to the presence or not of a hydrocarbonreservoir.

FIG. 9F is a graph schematically showing the phase, χ, relative to theHED transmitter AC drive signal, of the modeled TM mode decompositionplotted in FIG. 9E. It is apparent from FIG. 9B that the phase advancesat different rates for different hydrocarbon-reservoir resistivities.This again demonstrates the sensitivity of the electric TM modedecomposition given by Equation 7 to the presence of a hydrocarbonreservoir.

Although again not shown, curves similar to those shown in FIGS. 9E and9F but calculated for the TM mode decomposition given by Equation 8 alsodemonstrate the sensitivity of the magnetic TM mode decomposition to thehydrocarbon reservoir.

FIG. 10A is a graph schematically showing the ratio P of the curvesplotted in FIGS. 9A (radial electric field component), 9C (verticalelectric field component) and 9E (electric TM mode decomposition) for ahydrocarbon reservoir of resistivity ρ=100 Ωm to the correspondingcurves for which there is no detectable hydrocarbon reservoir (i.e. ρ=1Ωm). The curves are marked Er, Ez and TM^(E) for the radial electricfield, vertical electric field and electric TM mode decompositionrespectively. FIG. 10A demonstrates the sensitivity of the electric TMmode decompositions to the presence of the hydrocarbon reservoir as afunction of separation r and its similarity to the vertical electricfield data. This is apparent from the large diversions from unity forthe curve. As noted above, at a separation of r=11000 m, the electric TMmode decomposition is around 300-times greater with a ρ=100 Ωmhydrocarbon reservoir than when there is no detectable hydrocarbonreservoir (i.e. ρ=1 Ωm). The insensitivity of the radial electric fieldcomponent to the presence of the hydrocarbon reservoir (due to theairwave component dominating the signal) is also clear.

FIG. 10B is a graph schematically showing the difference in phase ∇χbetween the curves plotted in FIGS. 9B (radial electric fieldcomponent), 9D (vertical electric field component) and 9F (electric TMmode decomposition) for a hydrocarbon reservoir of resistivity ρ=100 Ωmand the respectively corresponding curves for which there is nodetectable hydrocarbon reservoir (i.e. ρ=1 Ωm). The curves are markedEr, Ez and TM^(E) respectively. FIG. 10B again demonstrates thesensitivity of the TM mode decomposition to the presence of thehydrocarbon reservoir as a function of separation r. This is apparentfrom the progressive increase in the absolute value of ∇χ. The relativeinsensitivity of the radial electric field component to the presence ofthe hydrocarbon reservoir is again seen.

Curves of the kind shown in FIGS. 9 and 10 which are derived from anactual CSEM survey of the kind shown in FIG. 6 data can be furtheranalyzed using standard techniques, for example, geophysical inversion,to produce subterranean resistivity maps of the area being surveyed.These analysis techniques can be broadly similar to techniquespreviously used in deep water surveys for radial electric field data ofthe kind shown in FIG. 9A for conventional CSEM survey data analysistechniques for surveys, for example.

Because in practice, subterranean strata configurations are generallynot as simple as those used in the model surveys described above, it canbe difficult to identify directly from curves of the type shown in FIGS.9E and 9F obtained from real surveys whether the curves contain featuresindicative of a buried hydrocarbon reservoir or merely features relatingto local larger scale background structures. In particular the kind ofTM mode decomposition data seen with a thin resistive hydrocarbonreservoir embedded in a uniform resistivity background can be similar tothat seen in a subterranean strata configuration comprising layers ofincreasing resistivity with depth. This kind of increasing-resistivitystructure is a feature of some submarine sedimentary basins, forexample, and can arise due to the progressive expulsion of conductivepore fluids with increasing depths by a rising overburden pressure.Accordingly, knowledge of the large scale background structure of thesubterranean strata in the area from which survey data are beinganalyzed is often helpful in order to determine reliably whetherfeatures in TM mode decomposition data are caused by a buriedhydrocarbon layer or whether they are caused by large scale backgroundstructures.

FIGS. 11A and 11B show two subterranean strata model configurations usedto show the difficulty in distinguishing between a thin resistivehydrocarbon reservoir (FIG. 11A) and a steadily increasing resistivitywith increasing depth (FIG. 11B). FIG. 11A shows a hydrocarbon-reservoirsubterranean model configuration which is similar to that of FIG. 8 forthe case where the hydrocarbon reservoir resistivity ρ=100 Ωm. However,the model subterranean strata configuration of FIG. 11A includes aninfinite depth of seawater, as opposed to the 100 m depth of seawater ofFIG. 8. In the increasing-resistivity subterranean strata configurationmodel of FIG. 11B, a section of seafloor 6 lies beneath an infinitedepth of seawater 4. The strata beneath the seafloor 6 comprise a seriesof sedimentary layers of increasing resistivity. A first layer 10 has auniform resistivity of 1 Ωm and a thickness of 400 m. A second layer 13has a uniform resistivity of 5 Ωm and a thickness of 1000 m. Beneath thesecond layer 13 is a third layer 15 which has a resistivity of 10 Ωm andextends downwardly for an infinite extent. An HED transmitter 22 and areceiver 125 are also shown.

FIG. 12A is a graph showing modeled curves for the electric TM modedecomposition data which are similar to and will be understood from theTM mode decomposition curves shown in FIG. 10A, but which are calculatedfor the hydrocarbon-reservoir subterranean strata configuration shown inFIG. 11A (marked TM^(HC)) and for the increasing-resistivitysubterranean strata configuration shown in FIG. 11B (markedTM^(non HC)). It is clear that the TM mode decomposition data calculatedfor the hydrocarbon reservoir model are similar to the TM modedecomposition data calculated for the increasing resistivity model. Thisdemonstrates the ambiguity that can arise with TM mode decompositiondata when attempting to distinguish between a subterranean strataconfiguration having a hydrocarbon reservoir and some other large scalesubterranean strata configurations.

Because of this possible ambiguity, analysis of survey data aimed atestablishing whether a subterranean strata configuration contains a thinresistive hydrocarbon reservoir will normally involve generating TM modedecomposition data such as that defined by Equations 7 (electric) or 8(magnetic). These response data are sensitive to the presence ofsubterranean hydrocarbon reservoirs, even in shallow water. However, inaddition, to determine reliably whether features of the TM modedecomposition data are indicative of a hydrocarbon reservoir or of thelocal background structure, it is helpful to determine how the TM modedecomposition data for a given subterranean strata configuration wouldappear if there were no hydrocarbon reservoir.

This analysis step, generally referred to as normalization, is usuallydone with the aid of background data. Background data are specific tothe area being surveyed and can be obtained in a variety of ways. Oneway is to model the EM survey performed to obtain the TM modedecomposition data with a model background subterranean strataconfiguration. The background model should be as close a match aspossible to the actual background structure in the area being surveyed.A comparison of the TM mode decomposition data with the background dataprovides difference data sensitive to the likely presence, extent andlocation of a subterranean hydrocarbon reservoir embedded within thebackground subterranean strata configuration. For example, if the TMmode decomposition data closely match the background data, there isunlikely to be a buried hydrocarbon layer. If, on the other hand, thereare differences, i.e. anomalies, in the TM mode decomposition datacompared to the background data, for example, an increased receiversignal amplitude, this could be quantitatively assessed in terms ofbeing indicative of a buried hydrocarbon reservoir. The variation inanomalies at different horizontal separations provides information onthe depth and extent of a hydrocarbon reservoir. For example, ifdifferences between the TM mode decomposition data and the backgrounddata are only apparent at large source-receiver horizontal separations,this is likely to indicate that the hydrocarbon reservoir is relativelydeeply buried. Similarly, a discontinuity in TM mode decomposition dataas a function of horizontal separation is likely to indicate a boundaryor edge of a hydrocarbon reservoir at the location of the discontinuity.

Suitable background models to use in generating background data can beobtained in several ways.

One way of obtaining the information required to construct a suitablebackground model is with conventional MT electromagnetic surveyingtechniques. As noted above, these techniques are capable of providinginformation on large scale background resistivity structures, eventhough they are generally unable to detect hydrocarbon reservoirsdirectly.

Another way of obtaining the information required to construct asuitable background model is from CSEM survey data. As mentioned above,it is the TE mode component of a transmitted signal which can provideinformation on background structure is a CSEM survey. TE mode responsedata can be obtained from similar linear combinations of gradients inelectric or magnetic field data to those give for the TM mode inEquations 7 and 8.

Equation 9, shown in FIG. 13A, defines a linear combination of agradient in electric field data along measured along y with respect to x(i.e. ∂E_(y)/∂x) and a gradient in electric field data measured along xwith respect to y (i.e. ∂E_(x)/∂y). Equation 9 defines combined responsedata which include only a TE mode dependence and no TM mode dependence.

Equation 10, shown in FIG. 13B, defines a linear combination of agradient in magnetic field data along measured along x with respect to y(i.e. ∂B_(x)/∂y) and a gradient in magnetic field data measured along ywith respect to x (i.e. ∂B_(y)/∂x). Equation 10 also defines combinedresponse data which include only a TE mode dependence and no TM modedependence.

The combined response data given by Equation 9 is referred to aselectric TE mode decomposition data and the combined response data shownin Equation 10 is referred to as magnetic TE mode decomposition data.

FIG. 12B is a graph which is similar to and will be understood from FIG.12A. However, whereas FIG. 12A plots data for the electric TM modedecompositions calculated for the model subterranean strata shown inFIGS. 11A and 11B, FIG. 12B plots data for the electric TE modedecompositions calculated for the same model subterranean strataconfigurations. The curve calculated for the hydrocarbon-reservoirsubterranean strata configuration shown in FIG. 11A is marked TE^(HC)and the curve for the increasing-resistivity subterranean strataconfiguration shown in FIG. 11B is marked TE^(non HC). It is clear thatthe TE mode decomposition data calculated for the hydrocarbon reservoirmodel is very different to the TE mode decomposition data calculated forthe increasing resistivity model.

Thus obtaining TE mode decomposition data of the kind defined inEquations 9 and 10 can help distinguish between different subterraneanstrata configurations, such as those shown in FIGS. 11A and 11B, whichprovide similar responses for the TM mode decomposition. Where this isdone, once the TM mode decomposition data (as defined by either Equation7 or 8) and the TE mode decomposition data (as defined by eitherEquation 9 or 10) are provided, they may be analyzed in an analogousmanner to the analysis techniques applied to conventional inline (TMresponse dominated) and broadside (TE response dominated) CSEM data.

However, it is noted that in shallow water, the use of TE modedecompositions to assist in distinguishing different large scalebackground structures is prone to the same difficulties associated withthe airwave component as described above. The impact of the airwavecomponent can be reduced to some extent by employing relatively lowfrequency EM signals. Low frequency signals suffer less attenuation asthey pass through the subterranean strata and so the airwave componentis not so dominant in the EM fields induced at a receiver by an HEDtransmitter driven by a low frequency AC current. Because of this, lowfrequency signals are capable of providing information on large scalebackground resistivity structures needed to generate a background model.(Low frequency signals are not so helpful in identifying thin resistivelayers directly due to the reduced spatial resolution associated withtheir long wavelengths.)

In other cases, an area to be surveyed will already be very wellcharacterized by previous surveying. For example, in a producingoilfield or oil province there is likely to be a wealth of existingseismic and well-log data. In these cases, background models can becalculated from a rock formation model. The rock formation model can becreated from the seismic data and then resistivities assigned to thevarious components in the rock structure using the resistivitiesobtained from well-log data. (If directly applicable well-log data arenot available, it may be possible to estimate resistivity values bycomparison with resistivity data from nearby wells in similar geologicalstructures.) This technique for obtaining the information required toconstruct a suitable background model will be especially suited toapplications in existing oilfields, such as monitoring long termdepletion of reserves.

When monitoring depletion, it may be sufficient to directly compare TMmode decomposition data taken at different times, e.g. several weeks ormonths apart, without use of a rock formation model. In other words, thebackground data used is data from a previous similar survey. Differencesin TM mode decomposition data taken at different times are indicative ofchanges in the hydrocarbon reservoir which have occurred between thetimes at which the data were taken. Because of this, this kind ofcomparison provides a useful monitoring tool. The TM mode decompositiondata taken at the earlier time thus effectively acts as background datafor comparing with the TM mode decomposition data taken at the latertime.

FIG. 14A schematically shows in plan view an example detector 40 whichmay be used in a receiver 125 during a CSEM survey of the kind shown inFIG. 6. The detector 40 allows electric TM mode decomposition data to beobtained. The detector 40 comprises two orthogonal arms. An x-arm 42defines the x direction while a y-arm 44 defines the y direction. Thex-arm 42 supports four electrodes labeled Vx1, Vx2, Vx3 and Vx4. They-arm 44 supports a further four electrodes labeled Vy1, Vy2, Vy3 andVy4. The electrodes are connected to conventional circuitry (not shown)for measuring and recording the electrical potential of each electrode.The electrodes form respective pairs, Vx1 and Vx2 form a first pair, Vx3and Vx4 form a second pair, Vy1 and Vy2 a third, and Vy3 and Vy4 afourth. Each pair is separated by the same distance δ and the mid-pointsof pairs on the same support arm are separated by a distance Λ.

Electrical potential measurements Vx1 and Vx2 (corresponding to theelectric potentials measured at the correspondingly labeled electrodesin FIG. 14A) allow the x component of electric field strength to bemeasured at the mid-point between Vx1 and Vx2,

$\left( {{{i.e.\mspace{11mu}{Ex}}\; 1} = \frac{{{Vx}\; 1} - {{Vx}\; 2}}{\delta}} \right).$A similar measurement of the x component of electric field can be madebetween electrodes Vx3 and Vx4,

$\left( {{{i.e.\mspace{11mu}{Ex}}\; 2} = \frac{{{Vx}\; 3} - {{Vx}\; 4}}{\delta}} \right).$Thus the gradient ∂E_(x)/∂x, given by

$\frac{{{Ex}\; 1} - {{Ex}\; 2}}{\Lambda},$can be determined. A similar calculation may be made for electrodes onthe y-arm to give a measurement of the electric TM mode decompositiondefined by Equation 7 as follows:

${\frac{\partial E_{x}}{\partial x} + \frac{\partial E_{y}}{\partial y}} \approx {\left( \frac{{{Vx}\; 1} - {{Vx}\; 2} - {{Vx}\; 3} + {{Vx}\; 4}}{\delta\Lambda} \right) + {\left( \frac{{{Vy}\; 1} - {{Vy}\; 2} - {{Vy}\; 3} + {{Vy}\; 4}}{\delta\Lambda} \right).}}$

This is shown only as an approximate identity since it assumes gradientsto be linear. In the case that the gradients are not linear over thelength scale of the detector there will be a slight inaccuracy due tothe gradients in the potentials and the gradients in the electric fieldsnot being sampled at the same location (i.e. at the mid points of therespective pairs of electrodes and the mid-point of the detectorrespectively).

FIG. 14B schematically shows in plan view another example detector 50which allows electric TM mode decomposition data to be obtained. Thedetector 50 again comprises an x-arm 52 and an orthogonal y-arm 54. Thex-arm 52 supports two electrodes labeled Vx1 and Vx2. The y-arm 54supports a further two electrodes labeled Vy1 and Vy2. A centralelectrode (i.e. common to both arms), labeled Vc, is located at thecenter of the detector. Each of the electrodes Vx1, Vx2, Vy1 and Vy2 areseparated from the central electrode Vc by the same distance Λ. Thedetector shown in FIG. 14B can be considered to be a modification of thedetector shown in FIG. 14A in which the electrodes Vx2, Vx3, Vy2 and Vy3of the detector 40 shown in FIG. 14A are coincident (i.e. δ=Λ) and soprovide the same electrical potential measurement Vc. Thus, using thedetector 50 shown in FIG. 14B, the electric TM mode decompositiondefined by Equation 7 may be calculated as follows:

${\frac{\partial E_{x}}{\partial x} + \frac{\partial E_{y}}{\partial y}} \approx {\left( \frac{{{Vx}\; 1} - {2{Vc}} + {{Vx}\; 2}}{\Lambda^{2}} \right) + {\left( \frac{{{Vy}\; 1} - {2{Vc}} + {{Vy}\; 2}}{\Lambda^{2}} \right).}}$

FIG. 14C schematically shows in perspective view an example detector 60which may be used in a receiver 125 during a CSEM survey of the kindshown in FIG. 6. The detector 60 allows magnetic TM mode decompositiondata to be obtained. The detector 60 comprises two orthogonal arms. Anx-arm 62 defines the x direction while a y-arm 64 defines the ydirection. The x-arm 62 supports two conventional coils for obtainingmagnetic field data, labeled Cx1 and Cx2. The coils are arranged in thexz-plane. The y-arm 64 supports a further two coils labeled Cy1 and Cy2arranged in the yz-plane. The coils are connected to conventionalcircuitry (not shown) for measuring and recording the magnetic fluxdensity through each coil. Thus Cx1 measures a first magnetic field By1along the y-direction, Cx2 measures a second magnetic field By2 alongthe y-direction, Cy1 measures a first magnetic field Bx1 along thex-direction and Cy2 measures a second magnetic field Bx2 along thex-direction. The center of the coils on each arm are separated by thesame distance Λ. Thus, using the detector 60 shown in FIG. 14C, themagnetic TM mode decomposition defined by Equation 8 may be calculatedas follows:

${\frac{\partial B_{y}}{\partial x} - \frac{\partial B_{x}}{\partial y}} \approx {\left( \frac{{{By}\; 2} - {{By}\; 1} - {{Bx}\; 2} + {{Bx}\; 1}}{\Lambda} \right).}$

FIG. 14D schematically shows in plan view an example detector 70 whichmay be used to allow electric TE mode decomposition data to be obtained.The detector 70 comprises two orthogonal arms. An x-arm 72 defines the xdirection while a y-arm 74 defines the y direction. The x-arm 72supports four electrodes labeled Vx1, Vx2, Vx3 and Vx4. The y-arm 74supports a further four electrodes labeled Vy1, Vy2, Vy3 and Vy4. Aswith the detector 40 shown in FIG. 14A, the electrodes are connected toconventional circuitry (not shown) for measuring and recording theelectrical potential of each electrode. The electrodes are disposed inpairs positioned one to either side of each end of the arms. Each pairis separated by the same distance δ and the mid-point of pairs on thesame support arm are separated by the same distance Λ. The detector 70allows suitable gradients in electric field to be measured so that theelectric TE mode decomposition defined by Equation 9 may be calculatedas follows:

${\frac{\partial E_{y}}{\partial x} - \frac{\partial E_{x}}{\partial y}} \approx {\left( \frac{{{Vx}\; 2} - {{Vx}\; 1} - {{Vx}\; 4} + {{Vx}\; 3}}{\delta\Lambda} \right) - {\left( \frac{{{Vy}\; 2} - {{Vy}\; 1} - {{Vy}\; 4} + {{Vy}\; 3}}{\delta\Lambda} \right).}}$

FIG. 14E schematically shows in perspective view an example detector 80which allows magnetic TE mode decomposition data to be obtained. Thedetector 80 comprises orthogonal arms 62 and 64. Each arm supports twocoils for obtaining magnetic field data, labeled Cx1, Cx2, Cy1 and Cy2.The detector 80 is similar to that shown in FIG. 14C, but with each coilbeing rotated 90 degrees about a vertical axis. Thus Cx1 measures afirst magnetic field Bx1 along the x-direction, Cx2 measures a secondmagnetic field Bx2 along the x-direction, Cy1 measures a first magneticfield By1 along the y-direction and Cy2 measures a second magnetic fieldBy2 along the y-direction. Again, the center of the coils on each armare separated by the same distance Λ. Thus, using the detector 80, themagnetic TE mode decomposition defined by Equation 10 may be calculatedas follows:

${\frac{\partial B_{x}}{\partial x} + \frac{\partial B_{y}}{\partial y}} \approx {\left( \frac{{{Bx}\; 2} - {{Bx}\; 1} + {{By}\; 2} - {{By}\; 1}}{\Lambda} \right).}$

It will be appreciated that many other arrangements of detectors willalso allow appropriate horizontal gradients in electric and/or magneticfield data to be measured so that the electric and/or magnetic TM and/orTE mode decompositions described above can be obtained. It will also beappreciated that in some surveys receivers may include detectorssuitable for measuring different combinations of combined response data.For example, a basic survey may use only a detector of the kind shown inFIG. 14A or 14B to measure only electric TM mode decomposition data forsimplicity. Another survey might similarly use only a detector of thekind shown in FIG. 14C for obtaining magnetic TM mode decompositiondata. However, to provide for improved sampling statistics, receiversemployed in another survey might have detectors for obtaining bothelectric and magnetic TM mode decomposition data. Furthermore, insurveys where TE data are to be used to provide background structuredata, a receiver having detectors for obtaining all four of thedecompositions defined in Equations 7, 8, 9 and 10 might be used.

By way of example, an analysis of the behavior of a detector of the kindshown in FIG. 14A for obtaining electric TM mode decomposition data willnow be considered.

FIG. 15A is a schematic gray scale representation of the magnitude ofmodeled electric TM mode decomposition data obtained per unit sourcedipole as a function of position in a 10-km square area of seafloor overthe model subterranean strata configuration shown in FIG. 11A. The dataare again scaled by the transmitter-receiver separation to provide anequivalent electric field. Data are modeled for an array of receiversarranged with a 200-m spacing on a regular Cartesian grid defined by Aand B axes. The HED transmitter is a point dipole located at A=B=0 withits dipole axis parallel to the A-axis and is driven by an AC drivesignal at a frequency of 0.25 Hz. The orientation of the detector ofeach receiver is assumed to be such that the x-direction is parallel tothe A-axis for all receivers. The detector electrodes are arranged suchthat Λ=1 m (see FIG. 14A). In a practical survey, the value of δ will bechosen to be large enough that the measurement precision allows anexpected magnitude of gradient to be measured between the electrodepairs. For the data shown in FIG. 15A, δ is taken to be vanishinglysmall.

FIG. 15B corresponds to FIG. 15A but shows the idealized theoreticalmodeled response using point detectors (i.e. Λ=δ=0).

FIGS. 15C and 15D are similar to FIGS. 15A and 15B, but show the phaseof the modeled electric TM mode decomposition data rather thanmagnitude.

It is clear from FIGS. 15A-D that the finite extent of the detectorsdoes not significantly affect the modeled data compared to the data fromidealized point detectors.

The curve marked Λ=1 m in FIG. 16A shows the percentage error δ in themodeled data shown in FIG. 15A compared to that in FIG. 15B as afunction of range (i.e. source-receiver separation) for receivers inlinewith the dipole axis (i.e. as a function of A, for B=0). The curvesmarked Λ=5 m, Λ=10 m, Λ=25 m and Λ=50 m show similar curves for greatervalues of Λ (as labeled). In each case, except for the discontinuity inthe vicinity of the source, the percentage error is less that 1%. Thisis also the case for all azimuths except for near the extreme φ=90degrees, for which the electric TM mode decomposition for a onedimensional (1D) earth is of zero magnitude. FIG. 16B is similar to FIG.16A, but shows phase data rather than magnitude data. Again, thepercentage errors are substantially less than 1%. These figuresdemonstrate that the TM mode decomposition approach to CSEM surveying isfeasible using realistic finite-sized detectors.

FIGS. 17A, 17B, 18A and 18B are similar to and will be understood fromFIGS. 15A, 15B, 15C and 15D respectively. However, whereas FIGS. 15A-15Dshow the modeled TM mode decomposition for an array of receivers havingΛ=1 m and each arranged with their x-axis parallel to the Λ axis (i.e.also parallel to the dipole axis), in FIGS. 17 and 18, the modeled dataare shown for Λ=10 m and with each receiver randomly oriented.

FIGS. 19A and 19B show the percentage errors ε in the modeled data shownin FIGS. 17A and 18A compared to those in FIGS. 17B and 18B respectivelyas a function of range for receivers inline with the dipole axis. Againexcepting the discontinuity in the vicinity of the source, thepercentage error is essentially 0% for all receivers. This is again alsothe case for all azimuths (except φ=90 degrees). This demonstrates, thatas noted above, the orientation of the x- and y-axis of each receiverrelative to the receiver azimuth does not affect the TM modedecomposition calculations. This is a great benefit of the TM modedecomposition approach in that it is not necessary to record or takeaccount of the orientation of a deployed detector.

FIGS. 20A and 20B are similar to FIGS. 19A and 19B but show thepercentage errors associated with detectors of the kind shown in FIG.14A with Λ=10 m but with a 3 m translational skew in both x and y (i.e.such that the x- and y-arms do not cross at their center) compared toidealized response data. It is clear that while the percentage errorsare relatively large for short ranges (i.e. where field gradients aresteepest), beyond 1 km all errors are less than 5%. This shows the TMmode decomposition data are relatively robust to specific electrodepositions within the detector.

FIGS. 21A and 21B are similar to FIGS. 20A and 20B but show thepercentage errors associated with detectors of the kind shown in FIG.14A with Λ=10 m but with a random variation in the angle between x- andy-arms of each of the detectors (i.e. their arms not perfectlyorthogonal) compared to idealized response data. Deviations fromorthogonality for the detectors comprising the receiver array arenormally distributed with a standard deviation of 1 degree. The errorsare a little larger than seen with translationally skewed arms (shown inFIGS. 20A and 20B), but are generally less than 10%. This shows the TMmode decomposition is also relatively insensitive to effects arisingfrom vibrations in the detector arms, for example.

The above analysis demonstrates the applicability of TM modedecompositions based on horizontal gradients in electromagnetic field to1D earth structures, i.e. strata of infinite horizontal extent. Inreality the earth is 3D and this can mean the TM and TE modecontributions to detected signals are mixed in a more complicated waythat for a simple 1D earth. The 3D earth typically comprisessubterranean strata that can be modeled as 3D structures embedded in a1D background. If a 3D structure embedded in a 1D structure isrelatively small, the TM mode decomposition will differ from that of the1D structure alone at the position of the embedded structure. Thus anartifact which identifies the location of the 3D structure occurs in thedata. If the 3D structure is larger, the TM mode decomposition will showan artifact at the embedded structure's boundary. This means the TM modedecomposition approach can be a powerful tool for detecting edges ofhydrocarbon reservoirs.

FIG. 22A shows in schematic vertical section a 3D model subterraneanstrata configuration. An HED transmitter 22 and a receiver 125 are alsoshown. The 3D model subterranean strata configuration includes a sectionof seafloor 6 beneath a 120-meter depth of seawater 4 having resistivity0.3 Ωm. The strata beneath the seafloor 6 comprise a finite-extenthydrocarbon reservoir 90 within an otherwise uniform backgroundstructure 92 of infinite horizontal and semi-infinite vertical extent.The uniform background structure has a resistivity of 1 Ωm. Thefinite-extent hydrocarbon reservoir has a vertical thickness of 50 m anda 6000 m×6000 m square extent in a horizontal plane, its upper face is1575 m below the seafloor and the reservoir has a resistivity of 100 Ωm.

FIG. 22B shows a schematic horizontal section through the center of thefinite-extent hydrocarbon reservoir 90 within the 3D model subterraneanstrata configuration shown in FIG. 22A. The projected position of thetransmitter 22 is marked by a cross 94.

FIG. 23A is a schematic gray scale representation of the magnitude ofmodeled electric TM mode decomposition data obtained per unit sourcedipole as a function of position in a 14-km square area of seafloor overthe 3D model subterranean strata configuration shown in FIGS. 22A and22B. The data are again scaled by the transmitter-receiver separation toprovide an equivalent electric field. As with FIG. 15A, data are modeledfor a regular square array of receivers arranged on a 200-m spacing on aCartesian grid defined by A and B axes. The HED transmitter is a pointdipole located at A=−5 km, B=0 km, with its dipole axis parallel to theA-axis. The transmitter is driven by an AC drive signal at a frequencyof 0.25 Hz. The position of the buried finite-extent hydrocarbonreservoir is shown in outline by a white line. The square reservoir'sedges are parallel to the A- and B-axis and are located at A=−6 km and 0km and B=−3 km and 3 km. Thus the transmitter is 1 km inside of the lefthand boundary of the reservoir as shown in FIG. 23A.

FIG. 23B is similar to FIG. 23A, but shows the phase of the modeledelectric TM mode decomposition data rather than magnitude.

The curve marked TM^(3D) in FIG. 24A plots the modeled data shown inFIG. 23A as a function of range (i.e. source-receiver separation) forreceivers inline with the dipole axis (i.e. as a function of A, forB=0). The curve marked TM^(1D) shows similar modeled data for asubterranean strata configuration which is similar to that shown in FIG.22A, but for which the hydrocarbon reservoir is of infinite horizontalextent (i.e. a 1D model). FIG. 24B is similar to FIG. 24A, but plots thephase data rather than magnitude data. In both FIG. 24A and FIG. 24B,the locations of the reservoir boundaries at A=−6 km (left-handboundary) and A=0 km (right-hand boundary) are indicated by dottedlines.

It can be seen that despite the 3D nature of the model subterraneanstrata, the TM mode decomposition still works and the combined responsedata are not significantly airwave contaminated. In addition, it can beseen from FIG. 24A that the reservoir edge at A=0 km generates anartifact in the data directly above it. When compared to the case withno edge (i.e. the 1D model), it can be seen that the effect of the edgeis to locally increase the TM mode decomposition signal. Beyond theedge, the 1D TM mode decomposition signal is greater because of thecontinued effect of the buried resistive hydrocarbon reservoir. For the3D case at ranges corresponding to receivers outside of the reservoir,the effect of the reservoir is reduced because of its limited horizontalextent between the transmitter and receiver and thus the signalenhancement is less. For smaller distances from the transmitter (i.e.either side of A=−5 km in FIG. 24A) the two curves are similar. This isbecause neither is sensitive to the buried reservoir (which is at adepth of 1575 m) for small offsets.

The artifact is less evident in the phase data shown in FIG. 24B. Aslight deviation between the curves can be seen above the edge at A=0km, and beyond this, as would be expected, the phase for the 1D modeladvance faster (i.e. shallower gradient). This is due to the resistivehydrocarbon reservoir spanning a greater extent between the transmitterand receivers in the 1D model compared to the 3D model for rangesoutside of the reservoir.

FIGS. 25A and 25B are similar to and will be understood from FIGS. 23Aand 23B. However, whereas FIGS. 23A and 23B show the absolute magnitudeand phase (relative to the transmitter signal) of the TM modedecomposition data, FIGS. 25A and 25B show the data normalized to auniform background subterranean strata (i.e. as shown in FIG. 22A butwithout the hydrocarbon reservoir 90). This is done in a manner similarto that described above in relation to FIGS. 10A and 10B. That is tosay, the ratio of the TM mode decomposition data shown in FIG. 23Arelative to that of the corresponding background model is plotted inFIG. 25A and the corresponding differences in phase in FIG. 25B. Theartifact at the edge of the reservoir is very clear in FIG. 25A as abright region adjacent edges of the reservoir (again indicated by awhite square).

FIGS. 26A and 26B are similar to and will be understood from FIGS. 24Aand 24B but plot normalized data corresponding to FIGS. 25A and 25Brather than the data shown in FIGS. 23A and 23B. The artifact associatedwith the edge of the reservoir in indicated by an arrow labeled E inboth figures.

It can be seen from FIG. 26A that the TM mode decomposition signals forthe model shown in FIG. 22A and the corresponding 1D model start todiffer from that of a uniform background model (no reservoir) at anoffset from the transmitter of around 3 km (i.e. A=−2 km). This isapparent from the departure from unity of both curves at this location.This is because at 3 km offset, the data are becoming sensitive to thehydrocarbon reservoir which is buried at a depth of around 1.5 km.Corresponding behavior is also seen for the phase plotted in FIG. 26B.Beyond this offset and in the vicinity of the edge, it can be seen thatedge tends to increase the TM mode decomposition data and retard thephase when compared to the case for the 1D model subterranean strataconfiguration.

FIGS. 27A and 27B are similar to and will be understood from FIGS. 23Aand 24A respectively. However, whereas in FIGS. 23A and 24A the TM modedecomposition data are scaled by range (i.e. multiplied by distance fromtransmitter to receiver) to provide an equivalent electric field, inFIGS. 27A and 27B the TM mode decomposition data are scaled byrange-cubed. This compensates for energy spreading associated withspherical divergence. The artifact associated with the edge is even moreapparent and effects at azimuths approaching 90 degrees are also moreclear (FIG. 27A).

FIGS. 28A and 28B are similar to and will be understood from FIGS. 27Aand 27A respectively but in which the TM mode decomposition data arescaled by range to the power four (i.e. equivalent electric field scaledby range-cubed). The edge artifact is more apparent still in thesefigures.

It is clear that not only can the TM mode decomposition approachidentify the presence of a subterranean hydrocarbon reservoir, it isalso able to identify edges of a buried reservoir having a finiteextent.

It will be understood that although the above description has focussedmore on electric TM mode decomposition data, magnetic TM modedecomposition data behave in a broadly similar fashion and could equallybe employed in a practical CSEM survey.

Furthermore, it will also be appreciated although the above descriptionis based on gradients in horizontal electric field seen at a receiver,because of the principle of reciprocity, schemes based on gradientsarising from the source can equally be employed. This can be achievedusing multiple horizontal electric dipole transmitters with anappropriate phase shift between them. These will be referred to asreciprocal arrangements (although it is of course arbitrary whicharrangement is considered primary and which is considered reciprocal).

FIGS. 29A and 29B schematically show in plan view an example transmitterconfiguration which may be used as a source during a CSEM survey. Forsimplicity, transmitters associated with gradient measurements along thex- and y-axes are shown separately in FIGS. 29A and 29B respectively andwill be referred to as first and second transmitter pairs respectively.For comparison, the corresponding configurations associated with thedetector shown in FIG. 14A are shown in the upper half of each figurewhile the example transmitter configurations are shown in the bottomhalves.

FIG. 29A shows first (Tx1) and second (Tx2) x-aligned horizontalelectric dipole transmitters for broadcasting signals to be received bya horizontal electric dipole detector (D). This arrangement reciprocatesthe dipole detectors formed by pairs of electrodes Vx1 and Vx2, and Vx3and Vx4 shown in the upper half of the figure (and FIG. 14A) and thesingle dipole transmitter T used with the detector arrangement shown inFIG. 14A. The centers of the transmitters Tx1 and Tx2 are separated by Λand the electrodes V1 and V2 forming the detector D by δ. Thetransmitters Tx1 and Tx2 are shown spaced apart along the x-axis,however in other examples they may overlap to some extent.

FIG. 29B shows first (Ty1) and second (Ty2) y-aligned horizontalelectric dipole transmitters for broadcasting signals to be received bythe horizontal electric dipole detector (D). This arrangementreciprocates the dipole detectors formed by pairs of electrodes Vy1 andVy2, and Vy3 and Vy4 shown in the upper half of the figure (and FIG.14A). Again, the centers of the transmitters Ty1 and Ty2 are separatedby Λ.

A calculation of the horizontal gradient along x of the x-component ofelectric field can made by driving Tx1 and Tx2 to simultaneouslybroadcast signals which are π out of phase. The gradient measurement isthe signal measured by the detector D divided by the separation betweenthe transmitters Λ. The π phase difference between the transmittersignals automatically provides a measurement representing the differenceof the transmitter responses. As an alternative, the transmitters Tx1and Tx2 could be driven at two different times (or simultaneously atdifferent frequencies if the response is not strongly frequencydependent) so that the response to each transmitter can be separated andthe difference between them formed. A calculation of the horizontalgradient along y of the y-component of electric field is similarly madeby driving Ty1 and Ty2 to simultaneously broadcast signals which are πout of phase and dividing the measured signal by Λ.

Because of the principle of reciprocity, these gradient measurementscorrespond to those described above in connection with Equation 7, and asimilar analysis can be applied to the data with similar results found.

One issue with this reciprocal arrangement is that the first and secondtransmitter pairs cannot be driven at the same frequency and at the sametime. This is because each gradient calculation would then becontaminated by the other. As a consequence, data must either becollected in two phases at different times or simultaneously atdifferent frequencies. This is so that the signals associated with therespective pairs of transmitters can be separated in the detector. Ifthe variation in coupling between the transmitters and detectors is astrong function of frequency, it will be preferable to collect data fromthe first and second transmitter pairs at different times. This could bedone by first collecting electromagnetic data using the firsttransmitter pair and then using the second transmitter pair, forexample, or by time domain multiplexing. By analogy with the abovediscussion of distorted receiver geometries, it is not critical to havethe centers of the first and second transmitter pairs at exactly thesame location (or following the same trajectory during a tow). Thecenters can be offset without significantly impacting the TMdecomposition. It is more important that the transmitters comprising thefirst and second transmitter pairs are close to parallel.

A second issue arises if the detector orientation is not aligned withrespect to the transmitter dipoles of the source array. To provideoptimum results in this case, the relative positions of each transmittershould be adapted such that a line connecting between the centers of thetransmitters of the first transmitter pair is parallel to the detectordipole. The positions of the transmitters forming the second transmitterpair should be similarly adapted. Accordingly, if the orientation of thedetector is not controllable, the relative positions of the transmittersshould be in order to provide the best results.

FIG. 30 shows another reciprocal transmitter configuration whichaddresses the issues arising the reciprocal arrangement shown in FIGS.29A and 29B. The configuration comprises a source formed from eightdipole transmitters (T1-T8) and a receiver comprising a single monopoleelectrode detector V (i.e. a potential sensor). In this arrangement, alltransmitters are driven simultaneously. Transmitters T1, T4, T5 and T8are driven in phase with one another. Transmitters T2, T3, T6 and T7 aredriven π out of phase from transmitters T1, T4, T5 and T8. The TM modedecomposition is given by

${{TMdecomposition} = \frac{V}{\Lambda*\delta}},$where V is the signal measured at the potential detector and Λ and δrelate to the transmitter separations as shown in the figure. In thisexample, the transmitter has a high degree of symmetry, although inpractice it would not be necessary for all separations for all pairs oftransmitters to be identical.

Because the TM mode decomposition can be made with all transmittersbroadcasting at the same time, there is no need for data to be collectedat different times, or for different frequencies to be used. Inaddition, because the detector is a simple potential sensor there are noissues relating to the detectors orientation with respect to thetransmitters. In addition, because there is only one detection channelneeded on the receiver, there are fewer issues regarding calibration andso on to be addressed. In effect, the TM mode decomposition (i.e. thesumming of the two horizontal gradients shown in Equation 7) aremeasured and added physically by virtue of the transmitter-detectorconfiguration, as opposed to being made mathematically.

An array of transmitters in a reciprocal configuration of the kinddiscussed above could be implemented in a practical CSEM survey byproviding three streamers towed behind a boat or submarine in mannersimilar to that shown in FIG. 6, for example. This can be done withconventional streamer equipment guided by “paravanes”, for example, suchas is done for seismic surveys. Alternatively each of the transmitterscould be towed one after another one.

It will be appreciated that while the above has described a reciprocalconfiguration for the electric TM mode decomposition (see Equation 7),similar reciprocal configurations can equally be made for the magneticTM decomposition (Equation 8) and the TE mode decompositions (Equations9 and 10) using appropriate magnetic/electric dipoles.

For conventional CSEM surveying based on geometric splitting of TE andTM mode responses, the most reliable data are collected with receiverspositioned over relatively narrow ranges of azimuth—e.g. within +/−15degrees of inline for the TM mode and within +/−15 degrees of broadsidefor the TE mode. This is because at intermediate azimuths, e.g. 45degrees, the TM and TE modes both contribute significantly to thedetected signal and so only the mixed response can be measured. Becausethe best data are only obtained for azimuths for which one modedominates the other, surveys can be relatively inefficient in their datacollection. However, the TM mode decomposition data described above canprovide reliable data over much wider ranges of azimuth. This is becausealthough the strength of the TM mode decomposition signal decreases withincreasing azimuth (due to its cos(φ) dependence), there is still no TEmode contribution. Accordingly, at 45 degrees azimuth, for example,although the magnitude of the TM mode decomposition signal will be lowerby a factor of √{square root over (2)} compared to that seen for inlineorientations, so long as the signal is strong enough to be measured, itcan still provide an indication of the subterranean strata response tothe TM mode which is uncontaminated by the TE mode. This allows useabledata to be collected over a wider range of azimuths than is possiblewith conventional surveying and so provides for more efficient surveys.So long as the transmitter provides a sufficiently strong signal thatthe magnitude of the TM mode decomposition data are sufficiently largecompared to any noise, useable data can be obtained for any azimuth.

It will be understood that whilst the above description describes atowed HED transmitter, the method would also be applicable in a fixedinstallation. For example, the method could be used to monitor changesto a hydrocarbon reservoir from which hydrocarbon is being drawn. Insuch cases it will be appropriate to employ one (or more) HEDtransmitter(s) in fixed positions relative to a receiver array ratherthan undertake frequent towed surveys. The HED transmitter(s) could beanchored to the seafloor or suspended from an oil-rig platform, forexample. In other examples, the HED transmitter(s) could be placed in ahorizontal well or borehole, e.g. a geotechnical borehole. In the caseof a producing oil field, the subterranean structures are likely to bewell known already from prior geophysical surveys and drilling results.Indeed, prior geophysical and geological information from the oil fieldcan be used to construct a background model as described above.

Although the above description has concentrated on the application ofembodiments of the invention to hydrocarbon reservoirs, it will beappreciated that the above described techniques may also be used forother CSEM surveys. This is because CSEM surveying is sensitive to thegeoelectric properties of the earth (e.g. electrical resistivity ofsub-surface strata), and not to hydrocarbon reservoirs in particular. Asa consequence, embodiments of the invention are equally applicable tosurveying for other resistive or conductive bodies (i.e. having aresistivity different to that of the background surrounding strata) andnot just for direct hydrocarbon detection.

Embodiments of the invention may be applied to structural mapping ofsalt or basalt bodies for example and also where more conductive strataare present in the earth, such as siliceous sediments. In these cases,the technique and mathematics (including the decompositions to overcomethe shallow water problem) are in essence the same.

In addition to surveying for oil and gas, examples of particularexploration environments in which CSEM surveying techniques of the kinddescribed above can be useful include the following:

Marine gas hydrates. There is interest in studying gas hydrate depositsfor a number of reasons. Firstly, they are considered to be a hazard tobe avoided while drilling the sea floor. This is because they can causethe subterranean strata to be unstable and lead to seafloor collapse,and because their release into the atmosphere can be environmentallydamaging as they are a source of powerful greenhouse gases. Secondly,such hydrates are a potential source of energy. Marine gas hydratestypically occur in the upper few hundred meters of the seafloor. Theirresistivities vary with hydrate content, but are typically on the orderof 2-6 Ωm. When applying the above described techniques to surveying formarine gas hydrates, higher frequencies and smaller offsets (which aremore sensitive to shallow structure) might be preferred duringacquisition of the CSEM data.

Salt bodies: In the oil exploration environment the mapping of saltbodies can be of interest. Such salt bodies usually have a large extent(several kilometers is not unusual), are highly resistive (few hundredΩm to a thousand Ωm) and can be several hundred meters to more than akilometer thick. It is quite common that hydrocarbon reservoirs arefound close to or beneath them. However mapping salt bodies can betechnically challenging using conventional seismic methods—although thetop of the bodies can in general be constrained, the high degree ofseismic scattering they cause can make the sides and bottom moreelusive. This leads to ambiguities in interpretation. In suchcircumstances marine CSEM methods can provide valuable complementaryinformation on the extent of the salt body.

For similar reasons, CSEM data can also be used to complement moreconventional exploration techniques in areas where intrusive volcaniclayers are present in the section.

Finally, it will be understood that the invention is equally applicableto surveying of freshwater, for example large lakes or estuaries, sothat references to seafloor, seawater etc. should not be regarded aslimiting and should be interpreted as covering lakebed, riverbed etc.Indeed the applicability of the invention to shallow water makes itideal for surveying shallow lakes.

REFERENCES

-   [1] GB 2382875 A-   [2] MacGregor, L. M. & Sinha, M. C. Use of marine controlled source    electromagnetic sounding for sub-basalt exploration. Geophysical    Prospecting, 48, 2000, 1091-1106.-   [3] WO 02/14906 A1-   [4] MacGregor, L. M., Constable, S. C. & Sinha, M. C. The RAMESSES    experiment III: Controlled source electromagnetic sounding of the    Reykjanes Ridge at 57° 45′ N. Geophysical Journal International,    135, 1998, 773-789.-   [5] Eidesmo, T., Ellingsrud, S., MacGregor, L. M., Constable, S.,    Sinha, M. C., Johansen, S., Kong, F-N & Westerdahl, H., Sea Bed    Logging (SBL), a new method for remote and direct identification of    hydrocarbon filled layers in deepwater areas. First Break, 20, 2002,    144-152.-   [6] Ellingsrud, S., Eidesmo, T., Johansen, S., Sinha, M. C.,    MacGregor, L. M. & Constable, S. Remote sensing of hydrocarbon    reservoirs by seabed logging (SBL): Results from a cruise offshore    Angola. The Leading Edge, 21, 2002, 972-982.-   [7] Chave, A. D. & Cox, C. S., Controlled electromagnetic sources    for measuring electrical conductivity beneath the oceans, 1. Forward    problem and model study. J. Geophys. Res., 87, 5327-5338, 1982.-   [8] Constable, S. C., Orange, A., Hoversten, M., Morrison, H. F.,    Marine magnetotellurics for petroleum exploration Part 1: A seafloor    equipment system, Geophysics, 63, 1998, 816-825.-   [9] U.S. Pat. No. 5,770,945-   [10] GB 2402745 A

1. A method of monitoring an area that contains a subterranean resistiveor conductive body, comprising: providing at least one horizontalelectric dipole transmitter and at least one receiver for obtainingelectric or magnetic field data at different times; measuring horizontalgradients in a first component of the electric or magnetic field dataalong a first direction at the different times; and measuring horizontalgradients in a second component of the electric or magnetic field dataalong a second direction at the different times.
 2. A method accordingto claim 1, further comprising comparing the measured horizontalgradients from the different times to identify changes in thesubterranean resistive or conductive body.
 3. A method according toclaim 2, wherein the changes in the subterranean resistive or conductivebody are changes in a boundary or edge of the subterranean resistive orconductive body.
 4. A method according to claim 2, wherein comparing themeasured horizontal gradients from the different times to identifychanges in the subterranean resistive or conductive body comprisescombining the horizontal gradients along the first and second directionsto generate combined response data for a first time and combining thehorizontal gradients along the first and second directions to generatecombined response data for a second time, and comparing the combinedresponse data for the first time with the combined response data for thesecond time.
 5. A method according to claim 1, wherein the firstcomponent of the electric or magnetic field data is the electric fieldstrength parallel to the first direction and the second component of theelectric or magnetic field data is the electric field strength parallelto the second direction.
 6. A method according to claim 1, wherein thefirst component of the electric or magnetic field data is the magneticfield strength perpendicular to the first direction and the secondcomponent of the electric or magnetic field data is the magnetic fieldstrength perpendicular to the second direction.
 7. A method according toclaim 1, wherein the first and second directions are orthogonal to oneanother.
 8. A method according to claim 1, wherein the at least onehorizontal electric dipole transmitter and at least one receiver areprovided in a fixed installation.
 9. A method according to claim 8,wherein the fixed installation comprises one or more horizontal electricdipole transmitters in fixed positions relative to an array ofreceivers.
 10. A method according to claim 1, wherein the at least onehorizontal electric dipole transmitter is anchored to the seafloor orsuspended from an oil-rig platform or placed in a horizontal well orplaced in a borehole.
 11. A method according to claim 1, wherein the atleast one horizontal electric dipole transmitter is a towed horizontalelectric dipole transmitter.
 12. A method of monitoring according toclaim 1, wherein the subterranean body is a hydrocarbon reservoir fromwhich hydrocarbon is being drawn.
 13. A method for obtaining hydrocarbonfrom an area that contains a subterranean hydrocarbon reservoir,comprising: penetrating the subterranean hydrocarbon reservoir with ahydrocarbon-producing well; extracting hydrocarbon from the subterraneanhydrocarbon reservoir using the hydrocarbon-producing well; providing atleast one horizontal electric dipole transmitter and at least onereceiver for obtaining electric or magnetic field data at differenttimes; measuring horizontal gradients in a first component of theelectric or magnetic field data along a first direction at the differenttimes; and measuring horizontal gradients in a second component of theelectric or magnetic field data along a second direction at thedifferent times; and continuing to extract hydrocarbon from thehydrocarbon-producing well as the measured gradients at different timesare used to monitor depletion of the reservoir.
 14. A volume ofhydrocarbon obtained from an area that contains a subterraneanhydrocarbon reservoir, the hydrocarbon obtained by: penetrating thesubterranean hydrocarbon reservoir with a hydrocarbon-producing well;extracting hydrocarbon from the subterranean hydrocarbon reservoir usingthe hydrocarbon-producing well; providing at least one horizontalelectric dipole transmitter and at least one receiver for obtainingelectric or magnetic field data at different times; measuring horizontalgradients in a first component of the electric or magnetic field dataalong a first direction at the different times; and measuring horizontalgradients in a second component of the electric or magnetic field dataalong a second direction at the different times; and continuing toextract hydrocarbon from the hydrocarbon-producing well as the measuredgradients at different times are used to monitor depletion of thereservoir.